Turbine powered electricity generation

ABSTRACT

A process is provided for separating syngas fuel into a CO-rich stream for feeding to oxyfuel combustor means of CO2 turbine means and a H2-rich stream for feeding to air-fuel gas turbine means for generating power provides opportunity to realize operating and equipment advantages.

FIELD OF THE INVENTION

The present invention relates to turbine-powered electricity supply.

BACKGROUND OF THE INVENTION

All patents, patent applications and other publications referred to herein are specifically incorporated herein by reference in their entirety.

Synthesis gas (syngas) is a gas mixture comprising primarily hydrogen (H₂), carbon monoxide (CO), water (H₂O) and carbon dioxide (CO₂), with minor amounts of other compounds (e.g., nitrogen, argon, hydrogen sulfide and methane). It can be produced by a number of known methods, including but not limited to coal gasification, steam methane reforming (SMR) and autothermal reforming (ATR).

In coal gasification, by way of non-limiting illustration, raw coal is pulverized in a mill and dried in a hot gas furnace. The pulverized and dried coal is pressurized in a lock hopper. The pressurized coal is mixed with oxygen and steam and the mixture is fed to a gasifier reactor. In the reactor, the coal particles heat up by pyrolysis, releasing volatiles and producing char. Volatiles from the pyrolysis and char react with oxygen to produce CO₂ and generate heat for gasification. Char reacts with steam to produce syngas. The gasification reaction is stopped by water quenching. Scrubbing water can be used to remove residual dust and impurities from the syngas. Coal gasification can be a major source for H₂. In order to increase the yield of H₂ the syngas is subjected to the water-gas shift reaction in which CO is reacted with H₂O to produce CO₂ and H₂: CO+H₂O

CO₂+H₂

In the steam reforming process, a mixture of water and hydrocarbon, typically natural gas, are contacted at a high temperature, for example, in the range of about 850° to about 900° C., and typically in the presence of a catalyst, to form a mixture of hydrogen and carbon monoxide. Using methane as the hydrocarbon, the theoretical stoichiometry for the steam reforming reaction is as follows: CH₄+H₂O

CO+3H₂

Among uses, syngas can be used as fuel for various turbines. In a gas turbine syngas is fed as a fuel together with air. There are three main turbine components:

1. An upstream axial rotating gas compressor;

2. A downstream turbine on a common shaft with the compressor;

3. A combustion chamber or area, called a combustor, in between 1, and 2. above.

Atmospheric air flows through the compressor that brings it to higher pressure. Fuel is mixed with the air in a combustor wherein it is ignited to produce high temperature working fluid. In the case of syngas as fuel, energy is added by spraying syngas into the air and igniting it. This high-temperature high-pressure working fluid enters a turbine where it expands down to an exhaust pressure, producing shaft work output in the process. The turbine shaft work is used to drive the compressor; the energy that is not used to drive the compressor exits in the exhaust gases to produce thrust. The purpose of the gas turbine determines the design so that the most desirable split of energy between the thrust and the shaft work is achieved.

As illustrated in U.S. Pat. Nos. 9,782,718 and 3,965,675, a gas turbine can be combined with a steam turbine. In this “combined” system, hot exhaust from the gas turbine produces steam in a heat recovery steam generator for feeding as a working fluid to a steam turbine. In the combined system, each of the gas turbine and the steam turbine can be utilized to produce electricity.

Gas turbine power plants and combined gas turbine/steam turbine power plants known as combined cycle power plants (CC) can use the burning of fossil fuel to generate required heat. These systems have known drawbacks, for example harmful air emissions. Natural gas power plants produce large quantities of pollutants, especially carbon dioxide. Coal fired plants add sulfur oxides, mercury and fine particles. These drawbacks are typically addressed by adding expensive, energy-intensive equipment to reduce or clean up emissions after they are produced. However, the required systems degrade performance, reliability and increase the cost of electricity and the total cost of the power plant. They are expensive to build, complex and energy intensive.

A turbine-powered electricity generator system under development in hopes of overcoming these drawbacks is a supercritical CO₂ (sCO₂) system that uses supercritical CO₂ (carbon dioxide) as the working fluid for the turbine(s). Using supercritical CO₂ as a working fluid in turbines, the high fluid density of sCO₂ enables much smaller hardware packages and efficiencies above 50%. It also facilitates high pressure carbon dioxide capture into the system without an added cost penalty, while carbon capture in conventional power plants is an expensive add-on that reduces system efficiency.

These systems are touted as a zero-emissions power generation system, as there is no smokestack and no water consumption though water is produced as a product of combustion. In the sCO₂ system, fuel is burned with pure oxygen of at least about 95% purity (oxy-combustion) instead of ambient air. This is preferable because air is almost 80% nitrogen and creates harmful NOx pollution when combusted. Oxy-combustion virtually eliminates NOx. High purity oxygen of at least about 95% purity produced using an Air Separation Unit (ASU) is combined with fuel and high pressure sCO₂ in a combustor and sent through a sCO₂ turbine where power is produced. sCO₂ and steam exit the turbine and flow into a heat exchanger where the steam is condensed out as liquid water and some of the sCO₂ is looped back to the combustor while the remainder exits the system through a high-pressure CO₂ pipeline.

These systems are much smaller than conventional power plants and the small footprint translates to lower capital costs. High pressure is used throughout the system and enables higher power densities as smaller components are used.

See Dennis, Richard “Overview of Supercritical Carbon Dioxide Based Power Cycles for Stationary Power Generation”. [online] Presented to: ARPA-E Workshop on High Efficiency High Temp. Modular Power Utilizing Innovative Designs, Materials, and Manufacturing Techniques Oct. 19-20, 2017 [retrieved 1-16-2019], Advanced Turbines and Supercritical CO₂ Power Cycles Programs US DOE Office of Fossil Energy National Energy Technology Laboratory, [online][retrieved Jan. 16, 2019][https://arpa-e.energy.gov/sites/default/files/1c%20-%20Dennis%20%28final %29.pdf]. See, also Wagman, David “This Power Plant Runs on CO₂” [online] IEE SPECTRUM, 30 May 2018, [retrieved Jan. 28, 2019] [https://arpa-e.energy.gov/sites/default/files/1c%20-%20Dennis%20%28final%29.pdf].

A non-limiting illustrative example of a sCO₂ plant is schematically described with reference to FIG. 1. Fuel gas stream 4 such as natural gas, syngas, etc., is fed to combustor 5, wherein it is combusted with high purity oxygen stream 8 of at least about 95% purity from air separation unit 6 in which air feed 7 is processed into the high purity oxygen stream 8. For natural gas as fuel gas stream 4, combustion occurs according to the reaction CH₄+2O₂→CO₂+2H₂O For syngas comprising H₂, CO and CH₄ as fuel gas stream 4, combustion occurs according to the reactions 2H₂+O₂→2H₂O CO+½O₂→CO₂ CH₄+2O₂→CO₂+2H₂O

Stream 9 comprises high pressure and temperature super critical CO₂ and steam which is fed to super critical CO₂ turbine 10. The turbine is connected to an electricity generator 11. The turbine exhaust stream 12 comprises super critical CO₂ and steam. Stream 12 flows through heat exchanger 13 in indirect contact with sCO₂ recycle stream 34 followed by second heat exchanger 15 and then through water separator means 16 for removal of condensed water 17. 23 is a closed loop cooler which keeps the cooling medium 36 relatively cool. The sCO₂ working fluid leaving the water separator 16, is compressed in CO₂ compressor 18, and then cooled in aftercooler 19 to remove heat of compression. Compressed and cooled sCO₂ in stream 20 is circulated by pump 21 for capture in stream 22 and recirculation in stream 34 then forwarded through regenerative heat exchanger 13 and finally back to combustor 5.

However, sCO₂ based power plants have disadvantages. One major disadvantage of these plants relates to the high capital cost (primarily due to oxygen requirements) and large power requirement inherent in conventional cryogenic air separation units required to generate oxygen. For example, see Global CCS Institute S. Wong “Module 3 CO₂ capture: Pre-combustion (decarbonisation) and oxy-fuel technologies, APEC Capacity Building in the APEC Region, Phase II Revised and updated by CO2CRC and ICF International. [online][retrieved 1-12-2019] [https://hub.globalccsinstitute.com/publications/building-capacity-co2-capture-and-storage-apec-region-training-manual-policy-makers-and-practitioners/module-3-co2-capture-pre-combustion-decarbonisation-and-oxy-fuel-technologies]

The present invention relates to a process for the treatment of syngas into a CO-rich stream and a H₂-rich stream and the use thereof resulting in significant advantages of reduced capital investment and operating costs for a sCO₂ based power plant, a combined gas turbine/steam turbine or a hybrid power plant based on the combination of a sCO₂ power plant and a CC power plant.

According to an embodiment, the process comprises:

-   -   a. feeding a separator feedstream comprising syngas to separator         means,     -   b. separating the separator feedstream in the separator means to         form a first, CO-rich stream and a second, H₂-rich stream,     -   c. feeding the first CO-rich stream as an oxyfuel combustor         feedstream to an oxyfuel combustor means wherein the oxyfuel         combustor feedstream is reacted with a high purity oxygen         feedstream of at least about 95% purity, and     -   d. feeding the second H₂-rich stream as an air-fuel combustor         feedstream to air-fuel combustor means wherein the air-fuel         combustor feedstream is reacted with air.         In the context of prior art systems that encouraged the         enrichment of CO₂ (e.g., by the water gas shift reaction) in         pre-combustion syngas for CO₂ capture therefrom, it was         unexpectedly discovered that the separation of syngas into a         CO-rich stream and a H₂-rich stream, wherein the CO-rich stream         is fed to an oxyfuel combustor for reaction with high purity         oxygen enables more efficient inherent post combustion CO₂         capture. Significant additional advantages are also realized         therefrom as described in more detail below. By feeding the         H₂-rich stream to air-fuel gas turbine means for generating         power, additional advantages can be realized, also as discussed         in more detail below.

According to another embodiment, the process comprises:

-   -   a. feeding a separator feedstream comprising syngas from a coal         gasifier to membrane separator means,     -   b. separating the separator feedstream to form a first, CO-rich         retentate stream, and a second, H₂-rich permeate stream,     -   c. feeding the retentate stream as an oxyfuel combustor         feedstream to oxyfuel combustor means wherein the oxyfuel         combustor feedstream is reacted with a high purity oxygen         feedstream of at least about 95% purity to form a supercritical         CO₂ working fluid,     -   d. feeding the supercritical CO₂ working fluid to supercritical         CO₂ turbine means for producing power, wherein the supercritical         CO₂ turbine means provides power to electricity generator means         for generating electric power,     -   e. feeding the permeate stream as an air-fuel combustor         feedstream to air-fuel combustor means wherein the air-fuel         combustor feedstream is reacted with air to form an air-fuel gas         turbine working fluid,     -   f. feeding the air-fuel gas turbine working fluid to air-fuel         gas turbine means for producing power, wherein the air-fuel gas         turbine means provides power to electricity generator means for         generating electric power,     -   g. feeding air-fuel gas turbine exhaust from the air-fuel gas         turbine means to heat recovery means wherein steam is formed,         and     -   h. feeding the steam formed in step g. as working fluid to steam         turbine means for producing power, wherein the steam turbine         means provides power to electricity generator means for         generating electric power.

According to a further embodiment, the process comprises:

-   -   a. feeding a separator feedstream comprising syngas from a steam         methane reformer to membrane separator means,     -   b. separating the separator feedstream to form a first, CO-rich         retentate stream, and a second, H₂-rich permeate stream,     -   c. feeding the retentate stream as an oxyfuel combustor         feedstream to oxyfuel combustor means wherein the oxyfuel         combustor feedstream is reacted with a high purity oxygen stream         of at least about 95% purity to form a supercritical CO₂ working         fluid,     -   d. feeding the supercritical CO₂ working fluid to supercritical         CO₂ turbine means for producing power, wherein the supercritical         CO₂ turbine means provides power to electricity generator means         for generating electric power,     -   e. feeding the permeate stream as an air-fuel combustor         feedstream to air-fuel combustor means wherein the air-fuel         combustor feedstream is reacted with air to form air-fuel gas         turbine working fluid,     -   f. feeding the air-fuel gas turbine working fluid to air-fuel         gas turbine means for producing power, wherein the air-fuel gas         turbine means provides power to electricity generator means for         generating electric power,     -   g. feeding air-fuel gas turbine exhaust from the gas turbine         means to heat recovery means wherein steam is formed, and     -   h. feeding the steam formed in step g. as working fluid to steam         turbine means for producing power, wherein the steam turbine         means provides power to electricity generator means for         generating electric power.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 is a schematic diagram of a supercritical carbon dioxide turbine plant;

FIG. 2 is a schematic diagram of a supercritical carbon dioxide plant combined with an air-fuel turbine/steam turbine plant.

DETAILED DESCRIPTION OF THE INVENTION

In the following detailed description, reference is made to the accompanying drawings, which form a part hereof. In the drawings, similar symbols typically identify similar components, unless context dictates otherwise. The illustrative embodiments described in the detailed description, drawings, and claims are not meant to be limiting. Other embodiments may be utilized, and other changes may be made, without departing from the spirit or scope of the subject matter presented herein.

All publications, patents and patent applications cited herein, whether supra or infra, are hereby incorporated herein by reference in their entirety to the same extent as if each individual publication, patent or patent application was specifically and individually indicated to be incorporated herein by reference. Further, when an amount, concentration, or other value or parameter is given as either a range, preferred range, or a list of upper preferable values and lower preferable values, this is to be understood as specifically disclosing all ranges formed from any pair of any upper range limit or preferred value and any lower range limit or preferred value, as well as, any range formed within a specified range, regardless of whether ranges are separately disclosed. Where a range of numerical values is recited herein, unless otherwise stated, the range is intended to include the endpoints thereof, and all integers and fractions within the range. For example, recitation of 1-5 is intended to include all integers including and between 1 and 5 and all fractions and decimals between 1 and 5, e.g., 1, 1.1, 1.2, 1.3 etc. It is not intended that the scope of the invention be limited to the specific values recited when defining a specific range. Similarly, recitation of at least about or up to about a number is intended to include that number and all integers, fractions and decimals greater than or up to that number as indicated. For example, at least 5 is intended to include 5 and all fractions and decimals above 5, e.g., 5.1, 5.2, 5.3 etc.

It is noted that, as used in this specification and the appended claims, the singular forms “a,” “an” and “the” include plural referents unless the content clearly dictates otherwise. Unless otherwise expressly indicated herein, all amounts are based on volume.

According to an embodiment, the process comprises:

-   -   a. feeding a separator feedstream comprising syngas to separator         means,     -   b. separating the separator feedstream in the separator means to         form a first, CO-rich stream and a second, H₂-rich stream,     -   c. feeding the first CO-rich stream as an oxyfuel combustor         feedstream to an oxyfuel combustor means wherein the oxyfuel         combustor feedstream is reacted with a high purity oxygen         feedstream of at least about 95% purity, and     -   d. feeding the second H₂-rich stream as an air-fuel combustor         feedstream to air-fuel combustor means wherein the air-fuel         combustor feedstream is reacted with air.

With reference to illustrative FIG. 2 of the drawings, 1 a is a source for producing syngas feedstream 1 b to separator means 2. The source of syngas feed can be any known source, for example, a steam reformer system or a coal gasification system. Steam reformer systems are known and are described, for example, in U.S. Pat. Nos. 3,479,298, 5,653,774 and 5,628,931. Coal gasification systems are also known and are described, for example, in U.S. Pat. No. 8,252,074B2, U.S. Pat. No. 8,758,458B2 and U.S. Pat. No. 9,388,348B2.

Syngas feed compositions are well known in the art and can vary depending on the source. By way of nonlimiting example, it is believed that syngas feed 1 b can comprise H₂, CO₂, CO, CH₄ and H₂O in the following amounts. The H₂ content can be about 20-65%. The CO₂ content can be about 2-25%. The CO content can be about 20-60%. The H₂O content can be about 5-40%. The CH₄ content can typically be about 0.1%-0.9%. It is understood that the syngas feed 1 b may contain minor amounts of contaminants, e.g., H₂S, NH₃, HCl, COS, and Hg, depending whether the syngas is gasified coal or reformed natural gas, and can be removed by known treatments. By way of example, contaminants could comprise less than about 0.5% of syngas feed 1 b.

Separator means 2 can be any known separator means suitable for the purpose of separating the syngas feedstream into a first, CO-rich stream 3 and a second, H₂-rich stream 26. For example, separator means can be membrane separator means or pressure swing adsorption means. Membrane separation is preferred.

Gas separation membranes and the operation thereof for separating gas mixtures are well known. See for example, U.S. Pat. No. 5,482,539. U.S. Pat. Nos. 4,990,168, 4,639,257, 2,966,235, 4,130,403, 4,264,338, and 5,102,432. Any known membrane that is operable under the conditions of operation to meet the noted product compositions can be used. For example, UBE membranes advertised for H₂ separations would be suitable, as would a polybenzimidazole (PBI) membrane. Reference is made, respectively, to Haruhiko Ohya et al, “Polyimide Membranes: Applications, Fabrications and Properties” by H. Ohya, V. V. Kudryavtsev and S. I, Semenova (Jan. 30, 1997) co-published by Kodansha LYD., 12-21 Otowa 2-Chome Bunkyo-Ku, Tokyo 112, Japan and Gordan and Breach Science Publishers S.A. Emmaplein 5, 1075 AW Amsterdam, The Netherlands, for the Ube membranes and to Jayaweera, Indira S. “Development of Pre-Combustion CO₂ Capture Process Using High-Temperature Polybenzimidazole (PBI) Hollow-Fiber Membranes (HFMs)”, 2017 NETL CO₂ Capture Technology Project Review Meeting, Aug. 21-25, 2017, [online] [retrieved Jan. 17, 2019], [https://www.netl.doe.gov/sites/default/files/2017-12/2I-S-Jayaweera2-SRI-PBI-Hollow-Fiber-Membranes.pdf], and “Celazole^(R) PBI”, [online] [retrieved Jan. 17, 2019], [https://pbipolymer.com/markets/membrane/].

As illustrated in FIG. 2, separator means 2 comprises membrane means 25 disposed therewithin. The syngas feedstream is fed to separator means on one side of the membrane means and is separated into separate streams by selective permeation of syngas components therethrough. As shown, the membrane is more permeable to the H₂ contained in the syngas feedstream than it is to CO. The membrane being more selective for H₂ permeation, permeate stream 26 is enriched in H₂ as compared to syngas feedstream 1 b, and retentate stream 3 is enriched in CO as compared to the syngas feedstream 1 b. Accordingly, stream 26 comprises a H₂-rich stream and stream 3 comprises a CO-rich stream. The CO-rich stream is then sent to a sCO₂ power plant 33 as discussed above.

Concepts of mixed-gas separation, gas permeability and selectivity are discussed in a number of publications, including “Materials Science of Membranes for Gas and Vapor Separation”, Edited by Yampolski et al, 2006 JohnWiley & Sons; “Pure and mixed gas CH₄ and n-C4H10 permeability and diffusivity in poly(1-trimethylsilyl-1-propyne)” Roy D. Raharjo et al, Polymer 48 (2007) 7329-7344, 2006 Elsevier Ltd., “Carbon Dioxide Separation through Polymeric Membrane Systems for Flue Gas Applications”, Colin A. Scholes et al, Cooperative Research Centre for Greenhouse Gas Technologies, Department of Chemical and Biomolecular Engineering, The University of Melbourne, VIC, 3010, Australia; and “Recent Patents on Chemical Engineering”, 2008, 1 52-66, 2008 Bentham Science Publishers Ltd.

The CO-rich stream 3 comprises primarily CO, with minor amounts of carbon dioxide and hydrogen.

After optional contaminant removal (not shown), stream 3 should comprise primarily CO and hydrogen. Stream 3 can also comprise a small amount of CO₂ and traces of remaining contaminants. For example, stream 3 can comprise at least about 35%, or at least about 50%, or at least about 65%, or at least about 80% CO. Having the benefit of the disclosure of the present invention, it is seen that the H₂ content of stream 3 depends on operational and plant design objectives. On that basis, it is believed that the stream 3 should comprise less than about 55%, or less than about 40%, or less than about 25%, or less than about 10% H₂. Stream 3 can also comprise a small amount of CO₂ and traces of remaining contaminants. Stream 3 should comprise less than about 0.01%, or less than about 0.001%, or less than about 0.0001%, or less than about 0.00001% of contaminants; and CO₂ should comprise less than about 25%, or less than about 15%, or less than about 10%, or less than about 5% of stream 3. Any upper limit for the CO content of stream 3 is considered to be limited only by the ability of technology to economically enrich stream 3 in CO. It is believed that using present technology, stream 3 can comprise up to about 90-95% CO.

Stream 3 is then fed as oxyfuel combustor feedstream 4 to oxyfuel combustor means 5, wherein it is combined and reacted with high purity oxygen stream 8 of at least about 95% purity from air separation unit means 6 for separating oxygen from air. The oxygen content of stream 8 comprises at least about 95%, at least about 97%, at least about 99%, or at least about 99.5%. Air separation units are well known, for example, as illustrated in U.S. Pat. Nos. 2,548,377, 4,531,371 and 4,382,366. See also, Rong Jiang, Analysis and Optimization of ASU for Oxyfuel Combustion [online] [retrieved 2-19-2019][http://ieaghg.org/docs/General_Docs/5oxy%20presentations/Session%207B/7B-05%20-%20R.%20Jiang%20(SASPG%20Ltd.).pdf]. and “History and progress in the course of time, [online] [retrieved Feb. 19, 2019] [https://www.linde-engineering.com/en/images/Air_separation_plants_History_and_progress_in_the_course_of_time_tcm19-457349.pdf]. Before the use of a separator means to separate hydrogen from the syngas feedstream 1 b in accordance with the present invention, a considerable portion of the oxygen produced in prior air separation units was consumed by reaction with H₂ contained in the combustor fuel stream 4. Combustion in accordance with an embodiment of the present invention, results in stream 9 comprised primarily of sCO₂ working fluid with a substantially reduced amount of steam. The sCO₂ content of the oxyfuel combustion exhaust in stream 9 will, of course, vary, depending on the amount of H₂ recovery in the membrane permeate and the amount of CO₂ in the membrane feedstream both of which affects the CO₂ content in the sCO₂ oxyfuel combustion exhaust. In any event, it can comprise at least about 50%, at least about 60% at least about 70%, or at least about 80% sCO₂, with the balance comprising H₂O, and contaminants such as N₂+Ar. An unexpected advantage of using a CO-rich fuel stream in accordance with the present invention to the oxyfuel combustor means 5 is that the oxyfuel combustor oxygen requirement can be significantly reduced, by way of nonlimiting example, by up to about 50 to 75%, depending on the source of the feed to separator means 2 (e.g., gasified coal or steam reformed methane, respectively) and the operating conditions and type of separator means 2 used. In addition, the oxyfuel combustor and sCO₂ turbine sizes can be significantly reduced due to the substantial reduction of the hydrogen fraction and hydrogen mass flow in stream 4 and consequently, after combustion with high purity oxygen in oxyfuel combustor means 5, a substantial reduction in steam fraction in stream 12.

Supercritical CO₂ (sCO₂) 9 is then fed to the inlet of a sCO₂ turbine means 10 wherein power is produced to power electricity generator 11.

Turbine exhaust 12 is then fed to regenerative heat exchanger means 13 for indirect cooling with cooled sCO₂ stream 34. The thus-cooled sCO₂ stream 35 is fed for further cooling in cooling means 15 for indirect cooling with cooling fluid 36. Cooled sCO₂ stream 37 is sent to condensed water separator means 16 for removing condensed water 17 from cooled sCO₂ stream 37. Since stream 37 comprises less water due to the separation of hydrogen from stream 1 b by separator means 2, cooling means 23 energy and equipment size requirements can be significantly reduced. Cooling fluid 36 for heat exchangers 15 and 19 is provided by cooling fluid cooling means 23. The sCO₂ working fluid leaving the water separator 16, is compressed in CO₂ compressor means 18, and then cooled in aftercooler means 19 to remove heat of compression. Compressed and cooled sCO₂ is circulated by pump 21 for capture in stream 22 and recirculation in stream 34 and then forwarded through regenerative heat exchanger 13 and finally back to oxyfuel combustor means 5. Recycle stream 24 is a working fluid for the optimum performance of the sCO₂ oxyfuel combustor and sCO₂ turbine. Recycling the supercritical CO₂ after reheating in regenerative heat exchanger 13 to oxyfuel combustor means 5 enables the supercritical carbon dioxide power cycle to operate with super critical CO₂ as the working fluid in turbine 10. The cycle is operated above the critical point of CO₂ so that it does not change phases (from liquid to gas), but rather undergoes density changes over small ranges of temperature and pressure. This allows a large amount of energy to be extracted at high temperature from equipment that is relatively small. For example, sCO₂ turbines can have a nominal gas path diameter an order of magnitude smaller than utility scale gas turbines or steam turbines.

Permeate, H₂-rich gas stream 26 is fed to a combined cycle system 27. Gas stream 26 comprises primarily H₂ and H₂O with small quantities of CO₂ and CO. Stream 26 can comprise at least about 40%, or at least about 50%, or at least about 60% or at least about 85% H₂. Having the benefit of the disclosure of the present invention, it is seen that the CO content of stream 26 depends on operational and plant design objectives. On that basis, it is believed that stream 26 should comprise less than about 10% CO, or less than about 5% CO, or less than about 3% CO, or less than about 1% CO with the balance comprising other components such as CO₂ and H₂O. Any upper limit for the H₂ content of stream 26 is considered to be limited only by the ability of technology to economically enrich stream 26 in H₂. It is believed that using present technology, stream 26 can comprise up to about 90-95% H₂.

Gas stream 26 is fed as an air-fuel combustor feedstream to air-fuel combustor means 45 of a known air-fuel gas turbine means comprising known turbine compressor section 39 and expansion section 40. As shown, working fluid air stream 43 is fed to compressor section 39. Compressed air stream 44 is fed to combustor means 45 wherein the compressed air and fuel gas stream 26 are mixed and combusted to form gas turbine working fluid 46. Working fluid 46 is then fed to expansion section 40 of the air-fuel gas turbine means wherein the working fluid expands, producing power which, in turn, drives electricity generator 29 and compressor section 39. Expanded exhaust 28 is then fed to known heat recovery steam generator means (HRSG) 31, wherein exhaust 28 indirectly heats a water stream to produce steam stream 42. The steam becomes the working fluid 42 which is fed to a known steam turbine system 32 that powers electricity generator 30. Condensed steam stream 41 is recycled back to the HRSG 31.

While known gas turbines typically burn carbonaceous fuels (e.g., natural gas or syngas) mixed with air to form a working fluid, processes in accordance with the present invention burn primarily H₂ with substantially reduced percentages of CO₂ and CO, and thus little or virtually no carbon dioxide is exhausted to the ambient environment in stream 32 a. Reduction or elimination of the carbonaceous part of the separator means syngas feed stream enables a significant downsizing of the combined cycle power generation equipment by not having to burn the fraction of carbon contained in natural gas and syngas.

EXAMPLES Example 1

Table 1 gives nonlimiting illustrative summary cases of potential approximate plant size reductions and therefore capital cost reductions due to the benefits of the invention when the separator means is a membrane. The summary cases correspond to two types of membrane separator means (membranes described in Examples 2 and 3 below), four separator means operating temperatures and two syngas sources. Table 2 is a representative material balance diagram explaining how savings were calculated.

TABLE 1 Respective plant size reductions according to membrane type, syngas source and operating temperature. Plant Red.¹ Plant Red.² Selec- Selec- sCO₂ sCO₂ Plant Red.³ System Mbr.* Syngas Temp. tivity tivity cooler turbine Combined CO₂ H₂ Type Source ° C. H₂/CO H₂/CO₂ Condenser and ASU Cycle Capture Recovery PI nat. gas 60.3 100.0 8.0 95.77% 72.36% 27.64% 91.3% 100.0% PI nat. gas 97.4 76.0 8.8 44.08% 32.97% 67.03% 98.4% 100.0% PI nat. gas 127.0 65.0 9.3 43.80% 32.79% 67.21% 98.3% 100.0% PI coal 60.3 100.0 8.0 63.73% 31.63% 68.37% 95.0% 100.0% PI coal 97.4 76.0 8.8 64.02% 31.99% 68.01% 95.0% 100.0% PI coal 127.0 65.0 9.3 63.57% 31.91% 68.09% 95.0% 100.0% PBI nat. gas 225.0 103.2 40.0 96.04% 72.44% 27.56% 95.0% 100.0% PBI coal 225.0 103.2 40.0 95.42% 48.16% 51.84% 95.0% 100.0% *PI = polyimide membrane and PBI = polybenzimidazole membrane ¹Plant size reductions for the sCO₂ plant cooler, condenser and heat exchangers. ²Plant size reductions for the air separation unit, sCO₂ combustor and sCO₂ turbine. ³Plant size reduction for the air-fuel turbine, HRSG and steam turbine.

Table 2

A B C D E F G H I  1 First CO-rich stream 3:  2 Membrane separator means: UBE polyimide combust³  3 Separator feedstream 1b: reformed natural gas to sCO₂ to sCO₂  4 Temperature: 60.33° C. scf scf  5 Super critical CO₂ H₂ recovery:  4.23% CO₂ 1.53 0.00  6 Combined cycle H₂ recovery: 95.77% CO 20.80  20.80   7 Total system H₂ recovery: 100.00%  CH₄ 0.86 0.86  8 Super critical CO₂ capture: 91.32% Ar + N₂ 0.17 0.00  9 H₂ 2.78 2.78 10 Membrane feedstream 1b: H₂O 0.37 0.00 11 scf combust¹ cool² 26.52  24.44  12 CO₂  2.63  0.00  0.00 13 CO 21.89 21.89  0.00 Second H₂-rich stream 26: 14 CH₄  0.88  0.88  0.00 combust⁴ cool⁵ 15 Ar + N₂  0.18  0.00  0.00 to CC to CC to CC 16 H₂ 65.66 65.66 65.66 scf scf scf 17 H₂O  8.76  0.00  8.76 CO₂ 1.10 0.00 0.00 18 100.00  88.43 74.42 CO 1.09 1.09 0.00 19 CH₄ 0.02 0.02 0.00 20 Ar + N₂ 0.01 0.00 0.00 21 H₂ 62.88  62.88  62.88  22 H₂O 8.39 0.00 839 23 73.48  63.99  71.27  ¹Combustible components in membrane feedstream 1b in FIG. 2 ²Hydrogen and water components in membrane feedstream 1b in FIG. 2 ³Combustible components in first CO-rich stream 3 in FIG. 2 to super critical CO2 stream 4 in FIG. 2 ⁴Combustible components in second H₂-rich stream 26 in FIG. 2 to combined cycle (CC) ⁵Hydrogen and water components in second H₂-rich stream 26 in FIG. 2 to combined cycle (CC)

Plant Size Reductions

ASU & sCO₂ power cycle plant size reduction=H23/C18=72.36%

Combined cycle (CC) plant size reduction=I11/C18=27.64%

Cooling/condenser/heat exchanger plant size reduction=I23/D18=95.77%

Example 2 Table 3

UBE Industries, Ltd., Polyimide Membrane H₂ and CO Permeability and Selectivity vs. Temperature Data 1000T⁻¹(K)⁻¹ selectivity GPU¹ GPU¹ GPU² GPU² Barrer³ Barrer³ ° F. x ° C. H₂/CO H₂ CO H₂ × 10⁻⁶ CO × 10⁻⁶ H₂ (×10⁻¹⁰) CO (×10⁻¹⁰) 77.91 3.35 25.51 134.78 0.31 0.002 4.135 0.031 4.135 0.0307 140.60 3.00 60.33 100.00 0.80 0.008 10.671 0.107 10.671 0.1067 207.27 2.70 97.37 75.95 1.80 0.024 24.010 0.316 24.010 0.3161 260.60 2.50 127.00 65.00 2.60 0.040 34.681 0.534 34.681 0.5336 212.00 2.68 100.00 74.88 UBE membrane maximum operating temperature is 100° C. ¹P/I (mm³/s/m²/Pa) Selectivity for 100° C. calculated by equation ²P/I (cm³/s/cm²/cm Hg) y = 0.0046x² − 1.3818x + 166.98 ³P (cm³-cm)/s/cm²/cm Hg) when I = 0.0001 cm membrane thickness Source: Polyimide Membranes - Applications, Fabrication, and Properties by Haruhiko Ohya, Vladislav V. Kudryavtsev and Svetlana I. Semenova (Jan. 30, 1997) page 250 Gordan and Breach Science Publishers S.A., Emmaplein 5, 107SAW Amsterdam, The Netherlands Pg. 250, FIG. 6.7, Temperature of pure gas permeation rates through asymmetric polyimide hollow fiber membrane . . . by UBE Industries, Ltd. (From Haraya, K. et al., Gas Separation and Purification, 1, 4 (1987))

UBE Industries, Ltd., Polyimide Membrane H₂ and CO Permeability and Selectivity vs. Temperature Data

TABLE 4 UBE Industries, Ltd., Polyimide Membrane H₂ and CO₂ Permeability and Selectivity vs. Temperature Data 1000T⁻¹(K)⁻¹ selectivity GPU¹ GPU¹ GPU² GPU² Barrer³ Barrer³ ° F. x ° C. H₂/CO₂ H₂ CO₂ H₂ × 10⁻⁶ CO × 10⁻⁶ H₂ (×10⁻¹⁰) CO (×10⁻¹⁰) 77.91 3.35 25.51 6.89 0.31 0.045 4.135 0.600 4.135 0.6003 140.60 3.00 60.33 8.00 0.80 0.100 10.671 1.334 10.671 1.3339 207.27 2.70 97.37 8.82 1.80 0.204 24.010 2.721 24.010 2.7212 260.60 2.50 127.00 9.29 2.60 0.280 34.681 3.735 34.681 3.7349 212.00 2.68 100.00 9.97 UBE membrane maximum operating temperature is 100° C. ¹P/I (mm³/s/m²/Pa) Selectivity for 100° C. calculated by equation ²P/I (cm³/s/cm²/cm Hg) ³P (cm³-cm)/s/cm²/cm Hg) when I = 0.0001 cm membranw thickness Source: Polyimide Membranes - Applications, Fabrication, and Properties by Haruhiko Ohya, Vladislav V. Kudryavtsev and Svetlana I. Semenova (Jan. 30, 1997) page 250 Gordan and Breach Science Publishers S.A., Emmaplein 5, 107SAW Amsterdam, The Netherlands, Pg. 250, FIG. 6.7, Temperature of pure gas permeation rates through asymmetric polyimide hollow fiber membrane . . . by UBE Industries, Ltd. (From Haraya, K. et al., Gas Separation and Purification, 1, 4 (1987)) In Tables 3 and 4, UBE Industries, Ltd. (UBE) is a Japanese multinational manufacturer of polyimide hydrogen separation membranes and have supplied membranes globally to industry for many years. H₂ and CO permeability values versus temperature are presented in Table 3 and H₂ and CO₂ permeability values are presented in Table 4. The GPU unit, also known as permeance, is a pressure normalized steady state flux for a given membrane thickness and is given as volumetric flow per unit area per second per unit differential pressure across the membrane. The Barrer unit, also known as permeability, is a steady state flux normalized for both membrane thickness and pressure differential across the membrane and is given as volumetric flow times membrane thickness, per unit area per second per unit differential pressure across the membrane. Selectivity is the ratio of the respective GPU or Barrer units, e.g., H₂/CO selectivity at 97.37° C. of 75.95 is determined by following ratio: 24.1010 cm³/cm²/s/cm Hg divided by 0.316³/cm²/s/cm Hg=75.95 It can be seen from the Tables 3 and 4 that H₂/CO selectivity is more sensitive to temperature change than H₂/CO₂ selectivity. The maximum operating temperature for the UBE polyimide membrane is 150° C. Operating an UBE polyimide membrane separator means at the maximum temperature of 150° C. increases overall system thermal efficiency. Further, the trendline equation in Table 3 calculates a H₂/CO selectivity of 63.33 at 150° C., a selectivity reduction of only 2.60% compared with 127° C. Furthermore, based a trendline algorithm for temperature vs. H₂ GPU values in Table 3, H₂ GPU is increased by about 30% at 150° C. compared with 127° C.

Example 3

TABLE 5 SRI International, Polybenzimidazole (PBI) Membrane H₂, CO and CO₂ Permeability and Selectivity vs. Temperature Data GPU¹ GPU¹ Barrer² Barrer² selectivity H₂ × CO × H₂ CO ° F. ° C. H₂/CO 10⁻⁶ 10⁻⁶ (×10⁻¹⁰) (×10⁻¹⁰) 437.00 225.00 103.0 80.0 0.775 80.0 0.775 ¹P/I (cm3/s/cm2/cm Hg) ²P (cm³ − cm)/s/cm²/cm Hg) when I = 0.0001 cm membrane thickness GPU¹ GPU¹ Barrer² Barrer² selectivity H₂ × CO₂ × H₂ CO₂ ° F. ° C. H₂/CO 10⁻⁶ 10⁻⁶ (×10⁻¹⁰) (×10⁻¹⁰) 437.00 225.00  40.0 80.0 2.00 80.0 2.00 ¹P/I (cm3/s/cm2/cm Hg) ²P (cm³ × cm)/s/cm²/cm Hg) when I = 0.0001 cm membrane thickness PBI DATA: The PBI data in Table 4 is available at: https://www.netl.doe.gov/sites/default/files/2017-12/2I-S-Jayaweera2-SRI-PBI-Hollow-Fiber-Membranes.pdf

Example 4

TABLE 6 Non-limiting examples of a range of concentrations of the first separated CO-rich stream and the second separated H₂-rich stream CO₂ CO CH₄ Ar/N₂ H₂ H₂S H₂O conc. conc. conc. conc. conc. conc. conc. PI membrane Reformed natural gas syngas Feed  2.6% 21.9% 0.9% 0.2% 65.7% 0.0%  8.8% First CO-rich stream at 60.33° C.  5.8% 78.4% 3.2% 0.7% 10.5% 0.0%  1.4% First CO-rich stream at 97.37° C.  5.9% 69.9% 2.9% 0.6% 18.3% 0.0%  2.4% First CO-rich stream at 127.00° C.  5.9% 64.9% 2.7% 0.5% 23.0% 0.0%  3.1% Second H₂-rich stream at 60.33° C.  1.5%  1.5% 0.0% 0.0% 85.6% 0.0% 11.4% Second H₂-rich stream at 97.37° C.  1.2%  1.6% 0.0% 0.0% 85.8% 0.0% 11.4% Second H₂-rich stream at 127.00° C.  1.1%  1.6% 0.0% 0.0% 85.8% 0.0% 11.4% PI membrane Gasified coal syngasFeed 10.9% 28.5% 0.1% 1.2% 27.0% 0.6% 31.7% First CO-rich stream at 60.33° C. 15.3% 46.4% 0.2% 2.0% 16.2% 1.0% 19.0% First CO-rich stream at 97.37° C. 15.6% 46.3% 0.2% 2.0% 16.1% 1.0% 18.9% First CO-rich stream at 127.00° C. 15.6% 46.0% 0.2% 2.0% 16.2% 1.0% 19.0% Second H₂-rich stream at 60.33° C.  4.1%  1.0% 0.0% 0.0% 43.7% 0.0% 51.3% Second H₂-rich stream at 97.37° C.  3.8%  1.3% 0.0% 0.0% 43.7% 0.0% 51.3% Second H₂-rich stream at 127.00° C.  3.6%  1.5% 0.0% 0.0% 43.7% 0.0% 51.3% PBI membrane Reformed natural gas syngas Feed  2.6% 21.9% 0.9% 0.2% 65.7% 0.0%  8.8% First CO-rich stream at 225° C.  8.6% 76.8% 3.2% 0.6%  9.5% 0.0%  1.3% Second H₂-rich stream at 225° C.  0.4%  1.3% 0.0% 0.0% 86.7% 0.0% 11.6% PBI membrane Gasified coal syngasFeed 10.9% 28.5% 0.1% 1.2% 27.0% 0.6% 31.7% First CO-rich stream at 225° C. 23.7% 65.5% 0.2% 2.8%  2.9% 1.4%  3.5% Second H₂-rich stream at 225° C.  1.6%  1.7% 0.0% 0.0% 44.4% 0.0% 52.1% Table 6 is a non-limiting illustration of membrane separator means performance which depends upon given operating conditions of syngas source, feed composition, membrane type and operating temperature. Accordingly, for the different operating conditions, CO concentration in the first CO-rich stream ranges from 46.0% to 78.4% and H₂ concentration in the second H₂-rich stream ranges from 43.7% to 86.7%%. 

The invention claimed is:
 1. A process comprising: a. feeding a separator feedstream comprising syngas from a steam methane reformer to membrane separator means, b. separating the separator feedstream to form a first, CO-rich retentate stream, and a second, H₂-rich permeate stream, c. feeding the retentate stream as an oxyfuel combustor feedstream to oxyfuel combustor means wherein the oxyfuel combustor feedstream is reacted with a high purity oxygen stream to form a supercritical CO₂ working fluid, d. feeding the supercritical CO₂ working fluid to supercritical CO₂ turbine means for producing power, wherein the supercritical CO₂ turbine means provides power to electricity generator means for generating electric power, e. feeding the permeate stream as an air-fuel combustor feedstream to air-fuel combustor means wherein the air-fuel combustor feedstream is reacted with air to form air-fuel gas turbine working fluid, f. feeding the air-fuel gas turbine working fluid to an air-fuel gas turbine means for producing power, wherein the air-fuel gas turbine means provides power to electricity generator means for generating electric power, g. feeding air-fuel gas turbine exhaust from the air-fuel gas turbine means to heat recovery means wherein steam is formed, and h. feeding the steam formed in step g. as working fluid to steam turbine means for producing power, wherein the steam turbine means provides power to electricity generator means for generating electric power.
 2. The process of claim 1, wherein the oxyfuel combustor means reacts high purity oxygen of at least 97% purity with the oxyfuel combustor feedstream to produce supercritical CO₂.
 3. The process of claim 1, wherein exhaust from the supercritical CO₂ turbine comprises sCO₂ and steam and is fed to water separation means for separating water from the exhaust, wherein the water separation means comprises the step of the exchange of heat from the exhaust to cooling fluid.
 4. The process of claim 1, wherein the high purity oxygen stream is at least 95% pure.
 5. The process of claim 4, wherein the CO-rich stream comprises at least 40% CO and the H₂-rich stream comprises at least 40% H₂.
 6. The process of claim 5, wherein the CO-rich stream comprises at least 50% CO and the H₂-rich stream comprises at least 50% H₂.
 7. The process of claim 6, wherein the CO-rich stream comprises at least 65% CO and the H₂-rich stream comprises at least 60% H₂.
 8. The process of claim 7, wherein the CO-rich stream comprises at least 80% CO and the H₂-rich stream comprises at least 85% H₂.
 9. The process of claim 5, wherein the oxyfuel combustor means reacts high purity oxygen of at least 97% purity with the oxyfuel combustor feed steam to produce supercritical CO₂.
 10. The process of claim 1, wherein the oxyfuel combustor means reacts high purity oxygen of at least 99% purity with the oxyfuel combustor feed steam to produce supercritical CO₂.
 11. The process of claim 10, wherein the oxyfuel combustor means reacts high purity oxygen of at least 99.5% purity with the oxyfuel combustor feed steam to produce supercritical CO₂.
 12. A process comprising: a. feeding a separator feedstream comprising syngas from a steam methane reformer to a membrane separator, b. separating the separator feedstream to form a first, CO-rich retentate stream, and a second, H₂-rich permeate stream, c. feeding the retentate stream as an oxyfuel combustor feedstream to an oxyfuel combustor wherein the oxyfuel combustor feedstream is reacted with a high purity oxygen stream to form a supercritical CO₂ working fluid, d. feeding the supercritical CO₂ working fluid to a supercritical CO₂ turbine for producing power, wherein the supercritical CO₂ turbine provides power to an electricity generator for generating electric power, e. feeding the permeate stream as an air-fuel combustor feedstream to an air-fuel combustor wherein the air-fuel combustor feedstream is reacted with air to form air-fuel gas turbine working fluid, f. feeding the air-fuel gas turbine working fluid to an air-fuel gas turbine for producing power, wherein the air-fuel gas turbine provides power to an electricity generator for generating electric power, g. feeding air-fuel gas turbine exhaust from the air-fuel gas turbine to a heat recovery steam generator wherein steam is formed, and h. feeding the steam formed in step g. as working fluid to a steam turbine for producing power, wherein the steam turbine provides power to an electricity generator for generating electric power. 